Incorporating Scarcity Pricing in Capacity Market Designs ___ 69
C. Advantages and Disadvantages of Adding Centralized Capacity Markets to Forward Reserve Requirements ___ 70
X. Conclusions ___ 72
Bibliography ___ 75
List of Acronyms ___ 85
Acknowledgements The authors would like to acknowledge the contributions of Sam Newell, Jose Garcia, and Serena Hesmondhalgh. Opinions expressed in this article, as well as any errors or missions, are the authors’ alone.

1 I. EXECUTIVE SUMMARY The Brattle Group has been commissioned by PJM Interconnection L.L.C. (“PJM”) to produce a whitepaper that compares and contrasts the PJM Reliability Pricing Model (“RPM”) with alternative power market designs and evaluates each design’s ability to maintain resource adequacy. We examine six alternative market designs, beginning with pure energy-only markets and progressing to more highly-structured designs that rely on administratively-determined capacity payments or explicit current or forward reserve requirements in possible combination with centralized capacity markets.

For each of these market designs, we summarize relevant U.S. and international experience and discuss the advantages and disadvantages of the various approaches.

Energy-Only Markets. In energy-only markets, resources obtain revenues solely through markets for energy and ancillary services without additional payments for capacity. Suppliers recover their investment costs through periodic severe price spikes. Pure energy-only markets do not rely on resource adequacy requirements to ensure a desired level of reliability; the level of reliability is determined solely through the marketplace. However, such a design has not been implemented, as real-world examples of energyonly markets rely on various out-of-market mechanisms to maintain reliability. Most energy-only market designs in the U.S. and internationally also cap market prices at levels well below the values required to let market forces choose the desired level of reliability. Examples: Alberta, Great Britain, Australia’s National Energy Market (“NEM”), Electric Reliability Council of Texas (“ERCOT”), Ontario.

Energy Markets with Administratively-Determined Capacity Payments. Adding an administratively-determined capacity payment to an energy market allows the market operator to maintain a desired level of capacity investment, while imposing price caps and other mitigation measures on energy markets to avoid severe price spikes. This market design does not directly impose reliability standards (e.g., reserve requirements) on load serving entities (“LSEs”); the achieved reliability level is the result of suppliers’ response to the administratively-set capacity payments. The absence of reserve requirements makes this the only market design that allows for differentiation of capacity payments to new and existing resources, though doing so introduces significant market distortions. By recovering the cost of capacity payments as an uplift charge on energy consumed rather than based on peak loads, capacity payment mechanisms also often distort price signals to consumers, thereby undermining demand response. Examples: Chile, Colombia, South Korea, Spain, Peru.

Energy Markets with Reserve Requirements (without Centralized Capacity Markets). This market design imposes an administratively-determined level of capacity reserves— ideally on a locational basis in transmission constrained market areas—that LSEs must maintain through either resource ownership or bilateral contracting. The reserve requirement imposed on LSEs—which is monitored and enforced during or immediately prior to the delivery period—creates a bilateral capacity market in which both demandand supply-side resources, as well as both existing and new capacity resources, are equally valuable.

A version of this market design is predominant in non-restructured U.S. power markets where utilities’ compliance with reserve requirements and reliability

2 standards is monitored and enforced through the state regulatory process. Examples: Southwest Power Pool (“SPP”), former Eastern U.S. power pools (NYPP, PJM, NEPOOL), some Canadian markets.

Energy Markets with Reserve Requirements and Centralized Capacity Markets. Adding a centralized capacity market to reserve requirements provides a transparent backstop procurement mechanism for the system operator and, in addition to asset ownership and bilateral contracting, offers LSEs a third option to satisfy or adjust their mandated reserve requirements. The capacity market also standardizes the capacity product, facilitates market monitoring, and provides greater liquidity and transparency than a bilateral market. While adding complexity in market design, these features are particularly beneficial in market environments with many small LSEs, retail competition, and migrating customer loads. Examples: New York Independent System Operator (“NYISO”); Midwest Independent Transmission System Operator (“MISO”).

Energy Markets with Forward Reserve Requirements (without Centralized Capacity Markets). In markets with a forward resource requirement (also often referred to as a forward resource adequacy standard), LSEs must demonstrate that they have acquired sufficient reserves one or several years in advance. The forward requirement—which should be imposed on a locational basis in transmission constrained market areas— creates a bilateral capacity market that allows sufficient time for additional capacity resources to come online. This increases competition, mitigates risk of market power abuses, reduces price volatility, and provides the system operator with sufficient time to contract bilaterally for backstop capacity on behalf of any deficient LSEs. Example: California ISO.

Energy Markets with Forward Reserve Requirements and Centralized Capacity Markets. This “forward capacity market” design combines the advantages of forward reserve requirements (including increased competition and lower price volatility) with those of centralized capacity markets (transparent market prices and backstop procurement mechanism, reduced transactions costs, and improved market monitoring). The considerable complexity of the market design increases the risk of design flaws, but offers features that are particularly valuable in market environments with many small LSEs, retail competition, and migrating customer loads.

Examples: PJM, ISO New England (“ISO-NE”), Brazil.

Each of these market designs has advantages in certain market and regulatory environments, which explain their implementation in various power markets around the world. In some cases, the market designs have existed long enough that we are able to evaluate some of their successes and failures. More often, the market designs are still relatively new and rapidly evolving, and have not yet been tested over the full investment cycle of capacity resources. Nevertheless, the experience to date provides some indication of how well these market designs will likely function over time.

The need for out-of-market mechanisms in many market designs is a step back in the effort to create competitive conditions in restructured power markets.

These out-of-market mechanisms include payments under reliability must-run (“RMR”) contracts, government investments in

3 generating capacity, and backstop mechanisms based on regulated cost recovery. Such interventions are attractive because they allow regulators or system operators to maintain reliability even when the market design has otherwise failed to attract sufficient capacity. However, these out-of-market mechanisms suppress market prices and create market distortions, which perpetuate and accelerate the need to expand the scope of out-of-market solutions to maintain reliability. A well-functioning market will attract enough capacity to provide an efficient level of reliability. In most power market designs, the determination of what constitutes an adequate level of capacity is based on traditional engineering and reliability standards.

This is the case even in capacity market designs that rely on downward-sloping demand curves, which are developed around a reliability target. Pure energy-only markets are fundamentally different from many other market designs in that they do not have predetermined reliability standards. Instead, they rely on customers to choose their desired level of reliability through the market mechanisms of interruptible rates and demand response. However, because these market mechanisms have not yet developed sufficiently to bring supply and demand into equilibrium and differentiate reliability across customers during shortage periods, real-world energy-only markets tend to rely on regulatory solutions for ensuring reliability, including out-of-market incentives and administratively-determined scarcity pricing mechanisms.

In fact, to achieve efficient price signals in any of the discussed market designs—including designs with capacity payments, reserve requirements, and centralized capacity markets—a regulatory solution generally is needed both to set proper prices during scarcity periods and to facilitate the development and integration of demand-response resources.

Power system operators and regulators have struggled to find mechanisms for setting scarcity prices at efficient levels, which is a particular challenge in the absence of significant demand response. Many energy-only markets have imposed price caps at levels set below the likely value of lost load (“VOLL”) and therefore do not allow for prices that can sustain needed investments. None of the power markets utilize mechanisms that increase scarcity prices gradually to the full level of VOLL as operating reserves diminish and demand curtailment becomes necessary. This creates considerable uncertainties about long-term resource adequacy in markets without explicit reserve requirements.

The liquidity and transparency of capacity markets is an important design consideration. Sole reliance on bilateral contracts and resource ownership can impose significant transaction costs on participants—particularly in markets with small LSEs, retail competition, and load migration. Bilateral markets are also more difficult to monitor for the exercise of market power. Without transparent market prices, new and small participants will have insufficient information to inform their investment and contracting decisions. The introduction of a standardized capacity product and centralized capacity market provides transparency, facilitates market monitoring and mitigation, and allows participants greater flexibility in meeting their reserve requirements and evaluating their investment decisions.

The combination of forward procurement and capacity markets with transparent price signals also reduces price volatility and revenue uncertainty which, at high levels, can reduce or delay needed investments.

Limiting capacity payments only to new resources and existing resources that otherwise would retire is sometimes offered as a solution to mitigate the cost of maintaining reliability. However,

4 this is not feasible in market designs that impose resource adequacy requirements on LSEs. Even in the absence of a capacity market, whenever such resource requirements are imposed in restructured markets, all capacity resources that can be used to satisfy the requirement will have the same capacity value. Even though an LSE’s embedded cost of existing resources or fixedpriced contracts may differ, all other resources would be able to obtain the full capacity value.

Differentiating capacity payments for new and existing resources is possible only if LSE resource adequacy standards are abandoned and replaced with administratively-determined capacity payments. In these market designs, the level of reliability achieved is solely a function of investment response to the offered capacity payment. This approach, currently used in Spain, introduces significant distortions of market prices that perpetuate the need for and can quickly expand the scope of capacity payments as existing resources would retire. (The expanding need for such payments can be significant because the all-in costs of retaining existing plants are high; they often are surprisingly close to, and can even exceed, the cost of new plants.) The long-term cost of an arrangement that limits capacity payments to new and about-to-retire resources will likely be higher due to market distortions and associated short-term and long-term inefficiencies.

PJM’s locational forward capacity market, RPM, has several advantages compared with the other market designs, considering that PJM operates in an environment that includes deregulated generation, transmission constraints, retail competition, and many (often small) LSEs with migrating customer loads. In this environment, centralized capacity markets, which also include the ISO-NE’s forward capacity market, provide significant benefits by facilitating the wholesale market participation of demand response resources and allowing for greater transparency, liquidity, market monitoring, backstop capacity procurement, and flexibility to address load migration compared to bilateral markets.

The most significant drawback of the RPM and other forward capacity market designs is their complexity, which increases implementation costs and the risk of design flaws. However, in the case of RPM, most of the design and implementation costs have been incurred already, many concerns about initial design parameters have been addressed, and the market has been shown to attract and retain capacity resources, including substantial amounts of demand-side resources. RPM and other market designs with centralized capacity markets also have the disadvantage that the clearly visible capacity price draws attention to the high cost of maintaining existing reliability targets.

However, replacing the forward capacity market with a purely bilateral resource requirement would not likely offer a lower-cost solution to maintaining reliability targets. Rather, reliance on self provision of LSEs’ resource requirements through bilateral contracts and resource ownership would simply make these costs less visible. To the extent that resource ownership or long-term bilateral contracts offer a lower-cost solution to maintain LSEs’ resource requirements and system-wide reliability standards, these self-provision options also exist under RPM and other centralized capacity market designs.

5 II. INTRODUCTION: RPM AND ALTERNATIVE MARKET DESIGNS A. SUMMARY AND PURPOSE OF RPM On June 1, 2007, PJM began its first delivery year under its new forward capacity market construct, the Reliability Pricing Model (“RPM”). The stated purpose of RPM is to enable PJM to obtain sufficient resources to reliably meet the needs of consumers within PJM while:1

Supporting LSEs using self-supply to satisfy their capacity obligations for future years;

Recognizing the locational value of capacity resources in the auctions; and

Using a backstop mechanism to ensure that sufficient generation, transmission, and demand response solutions will be available to preserve system reliability. The Brattle Group’s June 30, 2008 report Review of PJM’s Reliability Pricing Model (RPM), assessed the performance of RPM to date, evaluated how well RPM is addressing the infrastructure investment needs that it was intended to address, analyzed the key RPM design elements for their effectiveness in achieving RPM goals, and recommended modifications to numerous RPM design elements.2 As we noted in that report, the key design elements of RPM are:

A mandatory three-year forward resource adequacy requirement, based on target reserve margins for all LSEs;

A downward sloping (rather than a vertical) demand curve, called the Variable Resource Requirement (“VRR”) curve, that is anchored at an administrativelydetermined value for the Net Cost of New Entry (Net “CONE”) and that determines required reserve margins as a function of capacity prices;

Locational Deliverability Areas (“LDAs”) and locational capacity prices that are able to reflect the greater need for capacity in import-constrained areas;

Provisions that allow demand-side resources and new transmission projects to compete with generating capacity;

Explicit market power mitigation rules, including a must-offer requirement for existing generating resources, and Market Monitoring Unit (“MMU”) review of new entrant offers;

Performance metrics during the delivery year and peak periods; and

An opt-out mechanism under the Fixed Resource Requirement (“FRR”) alternative. Requiring capacity obligations to be self-supplied or procured through the capacity auction on a three-year forward basis is meant to roughly match the minimum lead time needed to bring new capacity resources online. It also allows for sufficient time to delay or cancel projects before irreversible major financial commitments have been made. The forward resource adequacy requirement in concert with clearing supply against a sloping demand curve is meant to improve price stability and reliability by providing meaningfully predicable forward market signals that can help avoid periods of extreme scarcity or excess capacity. It also forces existing resources to compete with a potentially large supply of new resources that can be brought online within three years.

In our 2008 RPM Report we found that RPM has been successful in encouraging investment in new and existing capacity to maintain resource adequacy both on an RTO-wide as well as on a local basis.3 We found that since RPM was implemented: (1) approximately 4,600 MW of capacity has been retained that otherwise would have retired; (2) almost 10,000 MW of incremental capacity has been committed; and (3) the volume of generation interconnection requests has grown to make an additional 33,000 MW of new generation projects eligible to participate in future RPM auctions. However, we also identified a number of concerns and recommended improvements to the RPM design, many of which have been addressed through recent modification of the RPM design.4 B.

OVERVIEW OF ALTERNATIVE MARKET DESIGNS Table 1 provides a brief summary of six market designs we will review in detail in Sections IV through IX. We present these alternatives in order of increasingly structured market designs that are targeted to ensure long-term resource adequacy, beginning with a discussion of the energyonly market and continuing with market structures that progressively add design components. 3 This analysis included the first five base residual auctions conducted within the RPM, for delivery years 2007/08 through 2011/2012. Because of the transitional period after RPM was implemented, only the last of these auctions was held a full three years ahead of the delivery year.

Reserve requirements are satisfied by LSEs through bilateral contracts or resource ownership.

The system operator monitors and enforces reserve requirements during delivery period, but there is no centralized capacity market. SPP; former power pools (NYPP, PJM, NEPOOL); other NERC reliability regions, including some Canadian markets.

Centralized capacity market facilitates forward capacity procurement by small LSEs and on behalf of deficient LSEs.

Forward commitment periods of centralized capacity markets (e.g., 3-4 years) are meant to roughly match the minimum lead time needed to bring new resources online (or the time needed to commit to, delay, or cancel planned projects before irreversible major financial commitments have been made).

9 As Table 1 shows, the most basic market design alternative to RPM is the “energy only market” (discussed in Section IV) in which resources recover their investment and operating costs solely through revenues from energy and ancillary services markets. Although regulators or market operators may set reserve margin targets, there is no enforcement of resource adequacy standards or planning reserve margin requirements. Investment costs are recovered and resource adequacy is achieved through very high prices during occasional periods of scarce supply.

Though several examples of energy-only market exist (e.g., ERCOT), none of these markets actually rely on a “pure” energy-only design. Rather, in most of these markets additional revenue sources are available to suppliers through mechanisms such as reliability-related backstop procurement contracts or cost-of-service-regulated resources. Because energy-only market designs tend to yield highly volatile market prices and occasional severe price spikes without guaranteeing resource adequacy, additional design components are often added in attempts to mitigate price volatility and ensure resource adequacy.

For example, there are several international examples of “energy markets with capacity payments” (e.g., Spain, as discussed in Section V), in which administratively-determined capacity payments are added to energy-only market designs in an attempt to attract needed supplies and facilitate resource adequacy. The added payments are intended to stimulate investments needed to maintain resources adequacy without imposing any reserve requirements. In most U.S. market areas, however, resource adequacy is ensured by imposing explicit reserve requirements on LSEs that are monitored and/or enforced during or immediately prior to each delivery period (e.g., peak season).

For example, in the Southwest Power Pool (“SPP”) and other “energy markets with reserve requirements” which have no centralized capacity markets, resource adequacy is ensured via reserve requirements satisfied by LSEs through bilateral contracts or resource ownership (as discussed in Section VI). In the majority of restructured markets that impose reserve requirements, however, RTO-administered centralized capacity markets have been added to improve pricing transparency, reduce transactions costs, facilitate market monitoring and mitigation, and provide a backstop capacity procurement by the system operator on behalf of deficient load serving entities.

Examples of such “energy markets with reserve requirements and centralized capacity markets” (Section VII) include NYISO and the Midwest ISO, which has recently adopted both a reserve requirement and a centralized capacity market.

In a number of power markets, the reserve requirement is monitored and enforced on a forward basis: one to several years ahead of the actual delivery period. In such “energy markets with forward reserve requirements” (Section VIII), load serving entities must show that resources have been procured one or several years prior to the actual delivery period. For example, CAISO currently imposes a one-year-ahead resource adequacy standard. Without a centralized capacity market, the resource adequacy standard creates a strictly bilateral market for reserve capacity in which LSEs own or contract for capacity resources.

Finally, in the most structured design we discuss, centralized capacity markets also have been added to market designs with forward resource requirements. Examples of such “energy markets with forward reserve requirement and centralized capacity markets” (Section IX) are PJM’s RPM and ISO New England’s Forward Capacity Market (“FCM”). Both of these designs enforce a 3-year forward resource adequacy standard that can be met through self-supply,

10 bilateral contracts, or capacity market purchases. Similar forward resource adequacy and capacity market designs are currently being evaluated in both New York and California.

These six market designs, as summarized in Table 1, are examined in detail in Sections IV through IX. However, we first discuss in Section III several topics useful for understanding the electric reliability and market design issues analyzed for the alternative market designs. III. ELECTRICITY MARKET FUNDAMENTALS AND DESIGN CONSIDERATIONS In this section we first review the cost structure of base-load and peaking resources. This is followed by a short discussion of reliability concepts and the need for reserve generating capacity. We then highlight differences in the cost recovery and timing of capacity prices in restructured and traditionally-regulated markets.

Finally, we discuss implications of price volatility and revenue uncertainty, pay-as-bid and uniform price auctions as alternative mechanisms to determine market clearing prices, and the feasibility of differentiating capacity payments to new and existing resources.

A. LOAD PROFILES AND THE COST STRUCTURE OF BASE-LOAD AND PEAKING RESOURCES Customers’ demand for power is cyclical on a daily, weekly, and seasonal basis, affected by patterns of commerce and weather. In most systems, the most extreme demands for power occur over the hottest few days each summer when air conditioning loads are greatest. Most hours of the year have power requirements within a much more moderate range. Figure 1 shows a typical load duration curve, illustrating how many hours of the year various load levels are reached. The total quantity of generating capacity that must be installed in the system is determined by the maximum load expected.

The mix of generation assets that can meet peak demand at the lowest cost depends on how often each unit would be economic to run. Baseload assets such as nuclear and coal have high fixed costs and low operating costs, potentially making them the lowest cost sources only if they are expected to operate at full capacity most of the time. Peaking assets such as combustion turbines (“CTs”) have low fixed costs and high operating costs, potentially making them the lowest cost sources only if they are expected to operate a small number of hours. Intermediate resources are those in between the two extremes.

Figure 1 also shows what portions of total capacity requirements would be supplied by these types of resources.

11 Figure 1 Illustrative Load Duration Curve, Showing Type of Generating Resources that can Supply Demand at or Above a Certain Level at Lowest Cost The market design discussions in this report focus on the means of attracting and retaining the resources that ensure system reliability, with particular attention to resource adequacy during peak hours.5 Peaking resources are rarely called upon to run. Traditionally, peaking capacity is supplied by CTs, but increasingly peaking resources are provided through demand-side resources: instead of supplying more power from generating plants during times of scarcity, some customers curtail their consumption according to a contractual agreement or in response to time-varying prices.

These demand-side resources can reduce system costs by reducing the need for peaking generators. Although some markets have been designed specifically to accommodate these demand-side resources because significant participation is expected and desired in future, many market designs have not yet incorporated these resources. B. SYSTEM RELIABILITY PLANNING AND THE NEED FOR RESERVES The reliability of the electrical system is measured by the frequency, duration, and magnitude of service interruptions or power quality problems. Overall reliability depends on two separate properties of the system: resource adequacy and system security.6 Resource adequacy means there is sufficient generation and transmission capacity in the electric system to supply the aggregate electrical demand at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.

If there is insufficient generating or transmission 5 A well-functioning electric market should attract the mix of resources with the lowest overall cost of supply, when accounting for both capital and operating costs. This will include a combination of baseload, intermediate, and peaking resources.

12 capacity to meet demand, then the system operator will enact emergency measures to maintain a stable power system, such as voltage reductions or load shedding. These measures result in disruptions of some customers’ service, but do not constitute a breakdown of system stability as long as the measures are implemented in a planned and controlled fashion.

A system can have adequate generation resources but still be unreliable due to insufficient system security. System security (or stability) is the ability of the electric system to withstand sudden disturbances, such as electric short circuits or unanticipated loss of system elements. For example, if the system has a single line outage that results in an uncontrollable cascade of additional outages, then a large number of customers will experience interruptions in service because the system was not sufficiently secure. Although security problems can have many possible causes not related to resource adequacy, shortage conditions exacerbate stability problems and make an electrical system more likely to experience cascading blackouts.

Forward system planning is an attempt to ensure resource adequacy. When determining how much capacity must be installed in order to reliably meet peak demands, system planners must forecast zonal loads and probable generation outage levels. These forecasts are made for future years, with high uncertainty around expected peak demands. System planners cannot be certain that the target capacity level will be sufficient to meet peak demand; their capacity target can only be anticipated to meet peak demand with a certain probability. Thus, with any particular target level of capacity, there will be a certain loss of load expectation (“LOLE”).

All else being equal, a lower target level of capacity would correspond with a higher LOLE, and vice versa. The North American Electric Reliability Council (“NERC”) has developed guidelines for conducting resource adequacy assessment, and the NERC regions implement their assessments in different ways.7 Most NERC regions have a LOLE reliability target of one day in ten years.8 Once the relationship between the levels of capacity and LOLE is estimated, the targeted LOLE can be translated into a target level of necessary capacity. If high reliability is desired, then the target capacity will be greater than the estimated peak load by some margin.

The planning reserve margin or capacity margin is the amount by which available capacity is expected to exceed normal future peak load as shown in Figure 1.9 As others have also pointed out, a consensus has not yet emerged on which market designs are best suited to ensure long-term resource adequacy in restructured power markets.10 The six designs discussed in Sections IV through IX are a representative range of options currently employed in power markets internationally.

7 NERC (2008c-d). 8 The exact meaning of this varies. For example, it can mean one event in ten years or 0.1 days each year. 9 Reserve margin is expressed as a percent of peak load while capacity margin is expressed as a percent of available capacity. 10 For example, see Roques (2007).

13 C. COST RECOVERY IMPACTS OF RETAIL AND WHOLESALE RESTRUCTURING Since the Public Utilities Holding Company Act (“PUHCA”) of 1935, and until a wave of industry restructuring began with the Public Utilities Resources Purchasing Act (“PURPA”) of 1978, the electric industry was regulated under a quite stable regulatory compact which granted electric utilities exclusive rights of supply in their service area, including all generation, transmission, distribution, and retail services.

The provision of these services was based on rates that reflected the utilities’ full cost of service, including all prudently-incurred costs related to generating facilities, reliability requirements, and reserve margins held by the utility. This traditional regulatory framework still provides full cost recovery for utilities operating generating plants in most U.S. power markets without retail competition. In these cost-of-service regulated settings, the role of power markets is limited to wholesale purchases or sales of power, which utilities undertake to supplement their cost-based generation activities.

These wholesale power transactions contribute to but are generally not needed to allow regulated utilities to recover capacity-related costs.

The role of power markets is quite different in regions with a restructured utility industry and retail competition.11 In such restructured markets, most utilities are no longer vertically integrated and, to the extent they own generating facilities, the cost of power plants is no longer recovered through cost-based rates. Rather, generating facilities need to operate on a “merchant” basis and recover costs through market-based (shortor long-term) bilateral contracts or spot market sales. Spot market revenues can be obtained in energy markets, ancillary service markets, and (where available) capacity markets.

The value of these revenue streams would also be reflected in bilateral contracts with load serving entities (“LSEs”) who rely on purchases from the wholesale market.

In fully restructured markets, investments in new generating facilities and retention of aging existing facilities will only be achieved if total market-based revenues are expected to equal or exceed the facilities’ total operating and (forward-looking) investment costs. This means that system-wide reliability and resource adequacy directly depend on the level of market-based revenues available to suppliers. If such revenues are insufficient to cover the total forwardlooking costs, new capacity will not be built and existing capacity will not be retained. This link between resource adequacy and the level of market-based revenues is much less pronounced in power markets without retail competition.

Many of these “wholesale-only” power markets remain dominated by traditionally-regulated, vertically integrated utilities, which recover most of their capacity costs through regulated retail rates. In these regions, reliability and resource adequacy typically are not dependent on the level of expected market-based revenues. Rather, resource sufficiency is ensured through the utilities’ long-term planning processes, which typically are subject to regulatory review processes and targeted to meet 11 In Europe, restructured power markets with retail competition are generally referred to as “liberalized” power markets.

14 applicable reserve requirements and reliability standards (e.g., as specified in market design No. 3, which is analyzed in Section VI below). D. TIME PROFILE OF CAPACITY PRICES IN REGULATED AND RESTRUCTURED POWER MARKETS An important but often ignored or misunderstood difference between regulated and fullyrestructured power markets relates to the time profile of capacity prices. In a cost-of-service regulated environment, retail rates will reflect the cost of generating capacity only after new generating resources are placed in service and reflected in utilities’ ratebases. This means there can be a lag of several years before regulated retail rates reflect the addition of expensive new capacity resources.

This lag causes a significant misalignment of retail prices and investment signals. Because demand continues to grow due to low rates, more new resources may be added to the system than will ultimately be needed when retail prices increase to reflect the added costs. This can lead to excess capacity, high regulated rates, and the risk of stranded costs or regulatory disallowances.

The time profile of capacity prices is quite different in restructured power markets. As in all other competitive markets, in restructured markets the market price for capacity will increase before new generating capacity needs to be added. As market participants perceive an approaching scarcity of generating capacity, market prices for capacity will increase and, in response, market participants will identify the lowest-cost resources that can operate profitably at the anticipated market prices. If capacity prices are reflected in retail rates or are otherwise made available to demand-side resources, this market-determined portfolio of resources will also include demand-response resources.

The fact that capacity prices increase before new resources are actually added to the system will dampen demand growth, which will reduce the resource need.

The fact that prices in restructured markets increase before any new capacity is added, can quickly raise public policy questions about the value and effectiveness of restructuring. Sharp anticipated increases in the market price for capacity in restructured markets can also lead to over-investment and the subsequent collapse of market prices (e.g., the boom-bust cycle experienced 5-10 years ago). Market designs based on forward resource requirements (market designs Nos. 5 and 6) have been developed specifically to reduce that type of price volatility and mitigate the risk of such boom-bust cycles.

E. IMPLICATIONS OF PRICE VOLATILITY AND REVENUE UNCERTAINTY The market designs we examine have varying degrees of price volatility and corresponding uncertainty of revenues and cost recovery. Uncertainty in suppliers’ revenues increases the financial risks and thus the cost of financing capital projects.12 In turn, investors require a higher rate of return on their investment, which will directly increase the price paid by customers. Caballero and Pindyck have found, for example, that “a doubling of industry-wide uncertainty 12 For example, see Minton and Schrand (1999), pp. 423-26.

15 raises the required rate of return on new capital by about 20 percent.”13 Market designs that help reduce price volatility and revenue uncertainty consequently will tend to reduce the cost of capacity investments.

Uncertainty also decreases available discretionary capital14 and creates a preference for more flexible, less capital-intensive generation assets. These assets with lower investment costs may have a higher total costs, but are still attractive to investors if faced with considerable uncertainty of recovering their fixed investment costs. Finally, since some of the uncertainty is anticipated to be resolved over time, investors will have an incentive to delay their investments. In other words, there is an “option value of waiting” because new information that becomes available over time increases the chances of making better investment decisions.15 The higher the uncertainty and the more of this uncertainty is anticipated to be resolved over time, the higher will be the value of delaying investments.

Market designs that reduce this uncertainty, will consequently also tend to facilitate investments on a more timely basis. Even though uncertainty and price volatility come with these costs, this does not mean that policy-makers should attempt to completely eliminate the risk exposure of market participants. Rather, total system costs will be minimized when the risks are assigned to the party most able to control that risk.16 Cost-effective public policy should not completely protect suppliers or customers from financial risks if they have some control over the causes of risk, because that would eliminate the incentives to reduce these risk-related costs.

However, risks beyond the control of market participants, such as weather and economic risks, should be fully reflected in market prices.

Price volatility and financial uncertainty result from several underlying risk factors. One factor is regulatory risk. Regulatory risk can be created by changing market designs. Regulatory risk can also be associated and exacerbated by perception of excessive regulatory discretion to intervene in markets as well as arbitrary or insufficiently transparent market rules. Other sources of uncertainty are the inherent price volatility in energy or capacity markets, the future amount of available supply, macroeconomic factors affecting demand, fuel and equipment costs, and weather. Generators are the parties most able to control overall generation investment levels and the availability of their resources during peak times.

This suggests that it is costeffective public policy to subject suppliers to at least some financial risk associated with these factors.

Finally, a large portion of the volatility in capacity prices and uncertainty in the amount of capacity needed is a function of customer demand uncertainty. Because customers are most able to control their demand levels, it would be sound policy to assign them associated risks. Traditionally, customers have had no exposure to the price volatility caused by the variance of 13 The finding is not specific to the electric industry. See Caballero and Pindyck (1996). 14 Minton and Schrand (1999), pp. 423-26. 15 Bernanke (1983), pp. 85-87. 16 Priest (2007).

16 their demand; instead, they paid a flat price for power no matter when they used it.

This is now changing with the introduction of demand response and dynamic pricing. F. MECHANISMS TO DETERMINE MARKET PRICES Many discussions of energy and capacity market designs also explore the advantages and disadvantages of different “auction designs” used to determine market prices and supplier compensation. These auction design alternatives include pay-as-bid approaches (prevalent in bilateral markets and RFP-based procurement processes) and uniform clearing price approaches (prevalent in RTO-administered energy markets and centralized capacity markets). High or low market prices for energy or capacity are sometimes attributed to the type of procurement mechanism that is used by the market administrator.

For example, New York legislators are currently exploring whether a pay-as-bid approach to clearing the NYISO energy market would result in lower prices than the currently used uniform market clearing price approach.17 The uniform pricing format has also been blamed for perceived high prices in centralized capacity markets. Similarly, a 30 to 50 percent retail rate increase associated with the end of a 10-year price cap period covering Illinois’ transition to deregulation was attributed to the “declining clock” auction format used to procure standard offer service. And some even attributed the high prices during the California power crisis to the uniform pricing design.

We believe these discussions over the advantages or harm done by different auction designs are either unfounded or greatly exaggerate their likely impacts and importance. It is the case that each auction design has offers practical or theoretical advantages over others under some circumstances, but the format of the auction design—including whether to rely on centralized capacity markets or rely solely on bilateral contracts to satisfy resource adequacy requirements— will not generally be a major factor influencing the observed market prices. It may seem at first blush that a pay-as-bid auction should reduce prices below uniform clearing price auctions because each supplier receives only the price they offered to sell at, rather than receiving the highest price that cleared the market.

This is not the case, however. Because the pay-as-bid market design does not force suppliers to bid their incremental costs, each supplier will submit an offer based on their best estimate of what the clearing price will be, and sales prices will converge to a range above or below the actual “market price.” This range will be very narrow in competitive markets (i.e., close to a uniform price), but wider and more uncertain in illiquid power markets.

The extent to which pay-as-bid approaches could lower prices compared to uniform pricing approaches was explored in great detail with respect to energy markets by a “blue ribbon panel” of experts with input from market participants and economists in the aftermath of the California power crisis. The panel concluded that switching from uniform to pay-as-bid pricing would not reduce prices and could even be harmful.18 A more recent, similarly detailed analysis of this 17 For example, see Megawatt Daily (2009a). 18 Kahn et al. (2001), p. 2. (“The expectation behind the proposal to shift from uniform to as-bid pricing— that it would provide purchasers of electric power substantial relief from the soaring prices of the electric